CN110234730B

CN110234730B - Invert emulsion drilling fluids with fatty acid and fatty diol rheology modifiers

Info

Publication number: CN110234730B
Application number: CN201780073843.6A
Authority: CN
Inventors: 维克兰特·瓦格勒; 阿卜杜拉·阿勒-亚米
Original assignee: Saudi Arabian Oil Co
Current assignee: Saudi Arabian Oil Co
Priority date: 2016-11-30
Filing date: 2017-11-30
Publication date: 2021-11-12
Anticipated expiration: 2037-11-30
Also published as: WO2018102495A3; US20200087563A1; US10767097B2; US20180148626A1; CA3043973A1; CN110234730A; EP3548580B1; EP3548580A2; US10526521B2; WO2018102495A2

Abstract

Various invert emulsion drilling fluid compositions are provided. The invert emulsion fluid is a water-in-oil emulsion that may include an invert emulsifier to stabilize the water-in-oil emulsion, a carboxylic acid of 16 to 18 carbons, a dimer fatty diol of 36 carbons, a polymeric fluid loss control agent; and inorganic minerals including one or more of lime, calcium chloride, and barite. The invert emulsion drilling fluid may be formulated to be substantially free of clay.

Description

Invert emulsion drilling fluids with fatty acid and fatty diol rheology modifiers

Technical Field

The present disclosure relates to drilling fluids for use in oil and gas exploration. More specifically, the present disclosure relates to compositions and uses of invert emulsion fluids comprising rheology modifiers.

Background

Conventional invert emulsion fluids for well drilling in oil and gas exploration typically contain clay in the formulation, where the clay acts as the primary rheology (viscosity) modifier. The clay may be an organophilic clay or an organoclay. The rheological properties of drilling fluids formulated using organophilic clays can deteriorate over time. In other words, fluids formulated with organophilic clays lose viscosity over time because the clays cannot maintain the necessary level of viscosity. One solution to the loss of viscosity over time is to add an excess of organophilic clay to the drilling fluid, or an excess of low specific gravity solids (LGS) to the drilling fluid, or both. However, adding excess clay, or LGS, or both, can increase drilling costs and can severely impact other important drilling fluid properties. These effects on cost or fluid properties or both may require further expensive treatment downhole or on the drilling fluid as a remedial measure. For example, adding excess LGS may increase the plastic viscosity and the volume percent solids, which may affect the rate at which the drill bit penetrates the formation, thereby increasing drilling costs.

The rheology of the drilling fluid changes as the depth of the well increases due to changes in pressure and temperature. This change can result in a change in the Equivalent Circulating Density (ECD) as the well is drilled down through the formation. These fluctuations in ECD can cause formation fractures when operating in narrow pore pressure and fracture gradient windows. This can result in formation damage and mud loss, thereby increasing drilling costs. Generally, minimizing rheological fluctuations using a thinner fluid results in lower ECD; however, the rheology of the fluid may need to be such that the properties of the fluid remove cuttings and help suspend drilling solids. A higher viscosity is required for debris removal and solids suspension, while a lower viscosity is required for better ECD, which are contradictory.

Disclosure of Invention

It has been recognized that there is a need for an invert emulsion drilling fluid having improved rheologyAnd rheological stability during drilling to balance the need for better ECD with debris removal and solids suspension. Certain embodiments relate to invert emulsion drilling fluid compositions and methods of drilling a wellbore using various invert emulsion drilling fluid compositions. In various embodiments, the invert emulsion drilling fluid may comprise a water-in-oil emulsion; an invert emulsifier for stabilizing the water-in-oil emulsion, the invert emulsifier being present in an amount capable of stabilizing the water-in-oil emulsion; a fatty acid having at least eight carbons and at least one carboxylic acid group; a 36 carbon dimer fatty diol; a fluid loss control agent; and inorganic minerals including lime, calcium chloride and barite (barium sulfate, BaSO)₄) One or more of (a).

In various embodiments, the fatty acid may be a 36-carbon dimer diacid having the general formula shown by formula 1.

Formula 1

In various embodiments, the 36-carbon dimer fatty diol may have a general formula shown by formula 2.

Formula 2

In various embodiments, the fatty acid may be a mixture of C16 and C18 saturated linear alpha carboxylic acids. An example of a C18 saturated linear alpha carboxylic acid is shown in formula 3.

Formula 3

In various embodiments, the fluid may be formulated with a volume ratio of oil to water of 5:95 to 95: 5. In various embodiments, the fluid may be formulated to have a density of 63lbm/ft³To 164lbm/ft³(pounds mass per cubic foot). In various embodiments, the fluid may be formulated to be free of clay and free of LGS. In various embodiments, the fluid may be formulated as calcium chloride (CaCl)₂) Salinity concentration of aqueous phase20 to 39 parts per million. In various embodiments, the fluid may be formulated with an amount of invert emulsifier ranging from 2lbm/bbl to 25lbm/bbl (pounds mass per barrel). In various embodiments, the fluid may be formulated in an amount of lime from 0.5lbm/bbl to 5 lbm/bbl. In various embodiments, the fluid may be formulated with an amount of fatty acids of at least 0.5 to 10 lbm/bbl. In various embodiments, the fluid may be formulated in an amount of 0.25 to 5lbm/bbl of fluid loss control agent. In various embodiments, the fluid may be formulated to have a 36-carbon dimer fatty diol amount of at least 0.5 lbm/bbl. In various embodiments, the oil may be selected from the group consisting of mineral oil, diesel fuel, and synthetic oil, and combinations thereof. In various embodiments, the fluid may be formulated to have a yield point greater than 15lbf/100ft². In various embodiments, the fluid may be formulated to have a low-shear yield point greater than 7lbf/100ft²。

In various embodiments, a method of drilling a wellbore using a invert emulsion fluid may include drilling a well in a subterranean formation using the invert emulsion fluid, wherein the fluid comprises a water-in-oil emulsion; an invert emulsifier for stabilizing the water-in-oil emulsion, the invert emulsifier being present in an amount capable of stabilizing the water-in-oil emulsion; a fatty acid having at least eight carbons and at least one carboxylic acid group; a 36 carbon dimer fatty diol; a fluid loss control agent; and inorganic minerals including one or more of lime, calcium chloride, and barite. In various embodiments, the fatty acid can be a 36-carbon dimer diacid similar to formula 1. In various embodiments, the 36-carbon dimer fatty diol may have formula 1, which is similar to formula 2. In various embodiments, the fatty acid may be a mixture of C16 and C18 saturated linear alpha carboxylic acids. In various embodiments, the oil to water volume ratio in the fluid may be from 5:95 to 95: 5. In various embodiments, the density of the fluid may be 63lbm/ft³To 164lbm/ft³. In various embodiments, the calcium chloride aqueous phase salinity concentration in the fluid may be 20 to 39 parts per million. In various embodiments, the fluid may be formulated with an inverse emulsifier of 2 to 25 lbm/bbl. In one of the various embodiments, the first and second electrodes are,the fluid may be formulated to a lime of 0.5 to 5 lbm/bbl. In various embodiments, the fluid may be formulated with fatty acids of at least 0.5 to 10 lbm/bbl. In various embodiments, the fluid may be formulated to have a fluid loss control agent of 0.25 to 5 lbm/bbl. In various embodiments, the fluid may be formulated to have a 36 carbon dimer fatty diol of at least 0.5 lbm/bbl. In various embodiments, the oil may be selected from the group consisting of mineral oil, diesel fuel, and synthetic oil, and combinations thereof. In various embodiments, the fluid may be formulated to have a yield point greater than 15lbf/100ft². In various embodiments, the fluid may be formulated to have a low-shear yield point greater than 7lbf/100ft²。

Drawings

The embodiments will be readily understood by the following detailed description in conjunction with the accompanying drawings. Embodiments are illustrated by way of example, and not by way of limitation, in the figures of the accompanying drawings.

Fig. 1 is a graphical representation of Plastic Viscosity (PV), Yield Point (YP), and low-shear yield point (LSYP) data for the three fluids shown in table 1A, according to various embodiments.

Detailed Description

Embodiments of the present disclosure describe an Invert Emulsion Fluid (IEF) for drilling in oil and gas exploration, wherein the fluid has a combination of fatty acids and fatty diol compounds for rheology modification. In some embodiments, the fluid may be formulated to be substantially free of clay. Other embodiments are described and disclosed herein.

In the following description, numerous specific details are set forth in order to provide a thorough understanding of various embodiments. In other instances, well-known processes and methods may not have been described in particular detail so as not to unnecessarily obscure the embodiments described herein. Additionally, descriptions of embodiments may omit certain features or details in order to avoid obscuring the embodiments described herein.

In the following detailed description, reference is made to the accompanying drawings which form a part hereof wherein like numerals designate like parts throughout, and in which is shown by way of illustration embodiments in which the subject matter of the present disclosure may be practiced. Other embodiments may be utilized, and reasonable changes may be made without departing from the scope of the present disclosure. The following detailed description is, therefore, not to be taken in a limiting sense.

The description may use the phrases "in some embodiments," "in various embodiments," "in certain embodiments," or "in embodiments," which may each refer to one or more of the same or different embodiments. Furthermore, the terms "comprising," "including," "having," and the like, as used with respect to embodiments of the present disclosure, are synonymous.

As used herein, when an invert emulsion fluid is "substantially free" of a component, the component is present in the composition in an amount such that it does not substantially impair the activity of the invert emulsion fluid and will impart the advantages described in the specific embodiments. For example, if the invert emulsion fluid is said to be substantially free of clay, the clay concentration in the invert emulsion fluid, as determined by quantitative evaluation with statistical significance, will be less than 5%. The term "about" as used herein means within an acceptable error range for the particular value as determined by one of ordinary skill in the art, which will depend in part on how the value is determined or determined, i.e., the limitations of the determination system.

Various embodiments disclosed herein relate to formulations of Invert Emulsion Fluids (IEFs) that are substantially free of organoclays and include rheology modifiers including combinations of fatty acids and fatty diols. The absence of organoclay as the primary viscosifier in IEF results in a fluid with lower plastic viscosity and minimal effect on ECD while providing greater rates of penetration into the formation. The absence of organoclay in the fluid may provide the fluid with a more gradual rheology that is necessary for deep well drilling with large temperature gradients. Advantages of various embodiments disclosed herein may be: lower concentrations of fatty carboxylic acids and fatty diols may provide higher low-end rheology than when the fatty carboxylic acids or fatty diols are used alone as rheology modifiers in invert emulsion fluids. Another advantage of various embodiments disclosed herein is: the rheology modifier combinations disclosed herein can provide good low end rheology, resulting in reduced barite sag and good wellbore cleanability. Another advantage of various embodiments disclosed herein is: the contaminating effect on the rheology of an IEF that is substantially free of organoclay can be minimized and any contaminating effect can be readily addressed by the drilling fluid conditioning agent.

Without being bound by theory, the fatty acid and fatty diol may have a synergistic effect that may provide enhanced low-end rheological properties to the substantially organoclay-free IEF, thereby improving the wellbore cleanup capacity and barite sag resistance of the fluid. This combination of rheology modifiers may also be used in conventional oil-based drilling fluids formulated with organoclays. In various embodiments, examples of fatty acids may include C16 to C18 fatty acids. In various embodiments, examples of fatty diols may include C32 to C36 dimer fatty diols.

The selective rheological properties of the IEF may predict how the IEF behaves in drilling purposes. These properties may include plastic viscosity, yield point and yield stress. For drilling purposes, PV may indicate drilling speed, where a smaller PV indicates a faster ability to drill the well, YP may indicate the cuttings carrying capacity of the IEF through the annulus (the wellbore cleanup capacity of the IEF), where a larger YP means a non-newtonian fluid with higher cuttings carrying capacity than a similar density but lower YP fluid; while yield stress may provide an indication of IEF's sensitivity to barite sag, with larger yield stress values generally having better resistance.

YP and PV properties can be evaluated using a Bingham Plasticity (BP) rheology model. YP may be determined by extrapolating the BP model to zero shear rate and may represent the stress required to move the fluid. Can be in lbf/100ft²YP is expressed in units. Typically, greater than about 15lbf/100ft²Is considered a suitable threshold for drilling purposes that provide suitable cuttings carrying capacity. When extrapolated to infinite shear rates, PV may represent the viscosity of a fluid and may be expressed in centipoise (cP). PV indicates solids in IEFAnd a smaller PV is generally preferred for formulation of IEF, as a smaller PV indicates a faster potential drilling rate. Both PV and YP can be calculated using 300 revolutions per minute (rpm) and 600rpm shear rate readings on a standard oilfield viscometer, and can be calculated by equations 1 and 2 shown below.

PV 600rpm reading-300 rpm reading [ Eq.1 ]

YP 300rpm reading-PV [ Eq.2 ]

With respect to yield stress, the value of yield stress may be defined by the parameter τ₀(Tau-zero) which is a parameter from the Herschel Buckley (HB) rheological model. In general, IEFs having relatively large yield stress values can be expected to have better sag resistance, which is desirable for drilling purposes. The parameter τ may be determined by fitting an HB model to a shear stress versus shear rate curve₀The curve may be plotted from the dial readings determined on a standard oilfield viscometer for the corresponding rpm. Tau is₀Can be expressed in units similar to YP. By calculating the low-shear yield point (LSYP) value using equation 3, τ can be estimated within reasonable engineering tolerances₀。

LSYP 2 (300rpm reading) -600rpm reading [ equation 3]

Equal to or greater than about 7lbf/100ft²The LSPY value of (a) may be considered an acceptable threshold for drilling purposes to minimize barite sag.

Various embodiments disclosed herein relate to invert emulsion drilling fluids. In various embodiments, the fluid may be: a water-in-oil emulsion, an invert emulsifier for stabilizing the water-in-oil emulsion, a carboxylic acid of 16 to 18 carbons (including a carboxylic acid of 18 carbons of formula 3), a dimer fatty diol of 36 carbons of formula 2, a polymeric fluid loss control agent; and inorganic minerals including one or more of lime, calcium chloride, and barite.

In various embodiments, the fluid may be formulated to have an oil-to-water ratio of about 5:95 to about 95: 5.

In various embodiments, the fluid may be formulated to be substantially free of clay. In various embodiments, the IEF is substantially free of organoclay. In various embodiments, the fluid may be substantially free of LGS.

In various embodiments, the 16 to 18 carbon carboxylic acids may include other fatty acids or combinations of these fatty acids having shorter chain lengths (e.g., C14 or C15) or longer chain lengths (e.g., C19 or C20). In certain embodiments, fatty acids having more than eight carbons may be used in the fluid formulation.

In various embodiments, the fluid may be formulated to be about 90lbm/ft³. In various embodiments, the fluid may be formulated as 63lbm/ft³To 134lbm/ft³。

In various embodiments, the fluid may be formulated as CaCl₂The salinity concentration of the aqueous phase is about 25 parts per million. In various embodiments, the fluid may be formulated as CaCl₂The salinity concentration of the aqueous phase is about 10 to 39 parts per million.

In various embodiments, the fluid may be formulated with an inverse emulsifier of about 10 lbm/bbl. In various embodiments, the fluid may be formulated with an inverse emulsifier of about 5 to 25 lbm/bbl. In various embodiments, the reverse emulsifier may be lemerumul^TMEmulsifiers (available from Halliburton Company, Houston, Tex., USA, headquarters). By way of example and not limitation, types of reverse emulsifiers may include polyamides with a hydrophilic-lipophilic balance of less than 11, sulfates, sulfonates, and carboxylates. In various embodiments, the invert emulsifier may be any suitable invert emulsifier used in formulating drilling fluids.

In various embodiments, the fluid may be formulated to be about 1.5lbm/bbl of lime. In various embodiments, the fluid may be formulated to a lime of about 0.5 to 5 lbm/bbl.

In various embodiments, the fluid may be formulated with carboxylic acids of 16 to 18 carbons at least about 0.25 lbm/bbl. In various embodiments, the fluid may be formulated with carboxylic acids of 16 to 18 carbons at least about 0.25lbm/bbl to 10 lbm/bbl.

In various embodiments, the fluid may be formulated to have a polymer fluid loss control agent of about 2 lbm/bbl. In various embodiments, the fluid may be formulated to have a polymer fluid loss control agent of about 1 to 10 lbm/bbl. In various embodiments, the polymeric fluid loss control agent may be

A fluid loss control agent. In various embodiments, the polymeric fluid loss control agent may be any suitable fluid loss control agent used in formulating drilling fluids.

In various embodiments, the fluid may be formulated to have a calcium chloride of about 28 to 32 lbm/bbl. In various embodiments, the fluid may be formulated to be about 83lbm/bbl to 87lbm/bbl of water. In various embodiments, the amounts of calcium chloride and water may vary outside of these ranges, and may depend on different additives in the fluid, the oil/water ratio, and the weight of the fluid.

In various embodiments, the fluid may be formulated to have a 36 carbon dimer fatty diol of at least about 0.25 lbm/bbl. In various embodiments, the fluid may be formulated to have a 36 carbon dimer fatty diol of at least about 0.25 to 10 lbm/bbl.

In various embodiments, the oil may be selected from the group consisting of mineral oil, diesel fuel, and synthetic oil, and combinations thereof.

In various embodiments, the fluid may be formulated to have about 220 to 225lbm/bbl of barite. In various embodiments, the amount of barite may vary outside of this range, and may depend on the oil-to-water ratio and the weight of the fluid.

In various embodiments, the fluid may be formulated to have a yield point greater than about 15lbf/100ft²。

In various embodiments, the fluid may be formulated to have a low-shear yield point greater than about 7lbf/100ft²。

Examples

As shown and described in the examples herein, the present disclosure describes Invert Emulsion Fluid (IEF) compositions with fatty acids and fatty glycol rheology modifiers.

In various embodiments, selected IEFs are formulated to be substantially free of organoclay. The fluid was formulated as a 90 pound per cubic foot (pcf) fluid with an oil to water ratio (OWR) of 70:30 and CaCl₂The Water Phase Salinity (WPS) concentration was 25 parts per million (Kppm).

Various 90pcf IEFs substantially free of organoclay were formulated using a combination of C16 to C18 fatty acids and C36 dimer fatty diol as rheology modifiers. The chemical structure of the C18 fatty acid moiety is shown in formula 3. The C16 fatty acid moiety has two fewer carbons in the straight chain. The chemical structure of C36 dimer fatty diol is shown in formula 2.

Table 1A provides formulation data with varying amounts of C16 to C18 fatty acids and three IEFs of formula 2. These formulations are labeled fluid 1 through fluid 3. For the formulations of stream 1 to stream 3, 146.6, 144.4 and 144.3 barrels of mineral oil (available from the Safra Company Limited, headquartered in saudi arabia) were added to the mixing tank, respectively. Mixing reverse phase emulsifier (LE SUPERMUL)^TM) Added to the mineral oil in an amount of 10 pounds per barrel (ppb) and then mixed for 5 minutes. Lime was added to the mixture in an amount of 1.5ppb and then mixed for 5 minutes. To this mixture, various amounts of C16 to C18 fatty acids were added, followed by mixing for 5 minutes. The amounts of C16 to C18 fatty acids of stream 1 to stream 3 were 0, 4.5ppb, and 3ppb, respectively. A fluid loss control agent (C:

available from Halliburton Company, houston, texas, usa at headquarters) was added to the mixture in an amount of 2ppb and then mixed for 5 minutes. The fluid loss control agent is a crosslinked methylstyrene/acrylate copolymer and can control fluid loss while minimizing the effect on plastic viscosity. To this mixture was added 29.5 lbs/barrel of CaCl₂And water in an amount of 84.9ppb, and then mixed for 5 minutes. Barite was added to the mixture in different amounts of 229.6ppb, 228.9ppb, and 229ppb (corresponding to stream 1, stream 2, and stream 3, respectively), and then mixed for 10 minutes. Mix the raw materialsTo the composition was added various amounts of formula 2, followed by mixing for 5 minutes. The amounts of formula 2 added to stream 1, stream 2 and stream 3 were 1.5ppb, 0 and 1.5ppb, respectively. Each formulation was hot rolled (after all ingredients were added to the formulation, placed in a pressurized high temperature, high pressure chamber and rolled at 250 ° f for 16 hours).

TABLE 1A

Each of the three IEFs of table 1A were tested at 3rpm, 6rpm, 100rpm, 200rpm, 300rpm, and 600rpm in a standard oilfield viscometer, and further tested for gel strength (3rpm test) and High Temperature High Pressure (HTHP) fluid loss. Examples of standard oilfield viscometers can include

Model 35 viscometer (available from Fann Instrument Company, Houston, Tex., USA, headquarters). The rheology of the Drilling fluid formulation is determined according to the American Petroleum Institute (API) Recommended practices (Recommended Practice) section 6.3, "Recommended Practice for Field Testing of Oil-based Drilling Fluids," section 13B-2(RP 13B-2). Samples of each drilling fluid were placed in thermostatically controlled viscometer cups. About 100 cubic centimeters (cm) is left in the cup, taking into account the fluid displacement due to the viscometer plumb ball (bob) and the sleeve³) The empty volume of (a). The determination is made with minimal delay from the preparation of the drilling fluid sample. The test was performed at any of 50 + -1 deg.C (120 + -1 deg.F.). The temperature of the sample was monitored and either intermittent or constant shear of 600rpm was used to stir the sample and obtain a uniform sample temperature. The viscometer dial reading is allowed to reach a steady value when the sleeve is rotated at 600 rpm. The time required to reach a stable value depends on the characteristics of the drilling fluid sample. Dial readings were recorded for the viscometer at 600 rpm. The rotor speed was reduced to 300 rpm. The viscometer dial reading was allowed to reach a steady value and the dial reading at 300rpm was recorded. The rotor speed was then reduced to 200rpm, 100rpm, 6rpm and 3rpm, and at each speedViscometer dial readings are allowed to reach a steady value and dial readings at 200rpm, 100rpm, 6rpm and 3rpm are recorded. PV, YP, and LSYP for the three fluids were calculated from the various measurements collected during this test and are shown in table 1B.

The gel strength of the drilling fluid was also determined according to API RP 13B-2 section 6.3. Samples of each drilling fluid were placed in a test viscometer as previously described. The drilling fluid was stirred at 600rpm for ten seconds, leaving the drilling fluid sample undisturbed for ten seconds. The viscometer's hand wheel was slowly and steadily rotated to produce a positive dial reading and the maximum reading thus obtained was recorded as the initial gel strength (10 second gel) in pounds force per hundred square feet. The drilling fluid sample was stirred at 600rpm for an additional ten seconds and allowed to stand undisturbed for ten minutes. The initial gel strength was determined repeatedly as described in this paragraph. The maximum reading obtained at present is recorded as ten minutes gel strength in pounds force per hundred square feet. The gel strength of the three drilling fluids is shown in table 1B.

HTHP fluid loss was determined according to API RP 13B-2 section 7.2. The HTHP fluid loss test may determine the static fluid loss behavior of a drilling fluid at high temperatures (e.g., 250F.). The test was performed using an HTHP filter press unit comprising a filter cell, a source of pressurized gas, a heating system, a high pressure filtrate collection vessel (maintained at an appropriate back pressure), and a filter media. The drilling fluid sample was stirred for five minutes using an in situ mixer and then poured into a filter tank leaving at least 2.5 cm of space in the chamber to allow the fluid to expand. Filter paper was installed in the filter cell and the filter cell was assembled, closing both the top and bottom valves. The filter tank was placed in an HTHP pressure filtration unit and connected appropriately to a high pressure filtrate collection vessel and a source of conditioned pressurized gas. The temperature of the drilling fluid sample within the filter tank was maintained at a test temperature of 250 ° f. A pressure of about 100 pounds per square inch (psi) was maintained until a test temperature of 250 ° f was reached. The pressure of the drilling fluid sample in the filter tank is then raised to a test pressure of 500psi and the timer for the filtration process is started. The filtrate was collected in a filtrate collection vessel for 30 minutes and measured using a measuring cylinderThe volume of the filtrate was measured in milliliters (mL). At 45.8 square centimeters (cm)²) The filtrate volume is corrected for the filtration area of (a). The HTHP filtration tank is typically half the standard filtration area or 22.58cm²The observed volume is therefore usually doubled and recorded. The results of the HTHP fluid loss measurements for the three drilling fluids are shown in table 1B.

TABLE 1B

Fig. 1 illustrates PV, YP, and LSYP data for the three fluids of table 1A, according to various embodiments. As can be seen from Table 1B and FIG. 1, the YP values of fluids 1 and 2 were less than that of fluid 3 (14 and 11 compared to 50). Further, LSYP values for fluid 1 and fluid 2 (4lbf/100 ft)²And 4lbf/100ft²) Much lower than 7lbf/100ft²By comparison, the value of fluid 3 is 17lbf/100ft². Since fluid 1 contains carboxylic acid of formula 2(C36 fatty diol, 1.5ppb) but no 16 to 18 carbons, while fluid 2 contains C16 to C18 fatty acid but no formula 2(C36 fatty diol), the use of carboxylic acid of 16 to 18 carbons alone or formula 2 as a rheology modifier is not applicable for the formulations of fluid 1 and fluid 2. In contrast, as shown in stream 3, when both 16 to 18 carbon carboxylic acids and formula 2 were added to the formulation, there was a synergistic effect and a significant effect on YP and LSYP. YP slave number of 11lbf/100ft²And 14lbf/100ft²Ramp to a value of 50lbf/100ft². LSYP from a value of 4lbf/100ft²Ramp to a value of 17lbf/100ft². These results are not proportional to the amount used, since stream 3 has 16 to 18 carbons of the carboxylic acid used in less than stream 2, while stream 3 has the same amount of formula 2 as stream 1. Thus, the combination of a carboxylic acid of 16 to 18 carbons with formula 2 improves fluid rheology for drilling fluid purposes in a disproportionate and unexpected manner, indicating a synergistic effect between the two rheology modifiers.

Ranges may be expressed herein as from about one particular value to about another particular value. When such a range is expressed, it is to be understood that another embodiment is from the one particular value and/or to the other particular value, and all combinations within the range. Where a range of values is described or referenced herein, the interval includes each intervening value between the upper and lower limit, as well as the upper and lower limit, and includes smaller intervals subject to any particular exclusion provided.

Where a method recited or referenced herein includes two or more defined steps, those defined steps may be performed in any order or simultaneously, unless the context excludes such possibility.

Although various embodiments have been described in detail for purposes of illustration, they are not to be construed as limiting, but rather as covering all changes and modifications within the spirit and scope thereof.

Claims

1. An invert emulsion drilling fluid comprising:

a water-in-oil emulsion;

an invert emulsifier in an amount to stabilize the water-in-oil emulsion;

a fatty acid, wherein the fatty acid is a mixture of C16 and C18 saturated linear alpha carboxylic acids;

a 36 carbon dimerized fatty diol, wherein said 36 carbon dimerized fatty diol has the formula:

a fluid loss control agent; and

inorganic minerals including one or more of lime, calcium chloride and barite.

2. The fluid of claim 1, wherein the fluid is formulated in a volumetric ratio of oil to water of 5:95 to 95: 5.

3. The fluid of claim 1, wherein the fluid is formulated to have a density of 63lbm/ft³To 164lbm/ft³Within the range of (1).

4. The fluid of claim 1, wherein the fluid is formulated to be free of clay and free of low specific gravity solids.

5. The fluid of claim 1, wherein the fluid is formulated as calcium chloride (CaCl)₂) The salinity concentration of the water phase is 20 to 39 million.

6. The fluid of claim 1, wherein the fluid is formulated in an amount of 2 to 25lbm/bbl of the reverse emulsifier.

7. The fluid of claim 1, wherein the fluid is formulated in an amount of lime from 0.5lbm/bbl to 5 lbm/bbl.

8. The fluid of claim 1, wherein the fluid is formulated with the fatty acid in an amount of at least 0.5 to 10 lbm/bbl.

9. The fluid of claim 1, wherein the fluid is formulated in an amount of 0.25 to 5lbm/bbl of the fluid loss control agent.

10. The fluid of claim 1, wherein the fluid is formulated to have an amount of the 36-carbon dimer fatty diol of at least 0.5 lbm/bbl.

11. The fluid of claim 1, wherein the oil is selected from the group consisting of mineral oil, diesel fuel, and synthetic oil, and combinations thereof.

12. The fluid of claim 1, wherein the fluid is formulated to have a yield point greater than 15lbf/100ft²。

13. The fluid of claim 1, wherein the fluid is formulated to have a low-shear yield point greater than 7lbf/100ft²。

14. A method of drilling a wellbore using an invert emulsion fluid, comprising:

drilling a well in a subterranean formation using an invert emulsion fluid, wherein the fluid comprises

A water-in-oil emulsion;

an invert emulsifier in an amount to stabilize the water-in-oil emulsion;

a 36 carbon dimer fatty diol, wherein said 36 carbon dimer fatty diol has the formula

A fluid loss control agent; and

inorganic minerals including one or more of lime, calcium chloride and barite.

15. The method of claim 14, wherein the fluid has a volume ratio of oil to water of 5:95 to 95: 5.

16. The method of claim 14, wherein the fluid has a density of 63lbm/ft³To 164lbm/ft³Within the range of (1).

17. The method of claim 14, wherein calcium chloride (CaCl) in the fluid₂) The salinity concentration of the water phase is 20 to 39 million.

18. The method of claim 14, wherein the amount of the reverse emulsifier in the fluid is from 2lbm/bbl to 25 lbm/bbl.

19. The method of claim 14, wherein the amount of lime in the fluid is from 0.5 to 5 lbm/bbl.

20. The method of claim 14, wherein the amount of the fatty acid in the fluid is from 0.5 to 10 lbm/bbl.

21. The method of claim 14, wherein the amount of the fluid loss control agent in the fluid is from 0.25 to 5 lbm/bbl.

22. The method of claim 14, wherein the amount of the 36-carbon dimerized fatty diol of the fluid is at least 0.5 lbm/bbl.

23. The method of claim 14, wherein the oil is selected from the group consisting of mineral oil, diesel fuel, and synthetic oil, and combinations thereof.

24. The method of claim 14, wherein the fluid has a yield point greater than 15lbf/100ft²。

25. The method of claim 14, wherein the fluid has a low-shear yield point greater than 7lbf/100ft²。